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Ultra Petroleum (NYSE:UPL)

Q1 2011 Earnings Call

May 06, 2011 11:00 am ET

Executives

Michael Watford - Chairman, Chief Executive Officer and President

Marshal Smith - Chief Financial Officer and Senior Vice President

Brad Johnson -

Douglas Selvius -

William Picquet - Senior Vice President of Operations

Kelly Whitley - Director of Investor Relations

Analysts

Brian Singer - Goldman Sachs Group Inc.

Leo Mariani - RBC Capital Markets, LLC

Ronald Mills - Johnson Rice & Company, L.L.C.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Raymond Deacon - Pritchard Capital Partners, LLC

David Tameron - Wells Fargo Securities, LLC

Subash Chandra - Jefferies & Company, Inc.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Brian Velie - Capital One Southcoast, Inc.

Michael Bodino - Global Hunter Securities, LLC

Andrew Coleman - Madison Williams and Company LLC

Noel Parks - Ladenburg Thalmann & Co. Inc.

Operator

Good day, ladies and gentlemen, and welcome to the Ultra Petroleum Corporation First Quarter 2011 Earnings Conference Call. My name is Amika, and I'll be your operator for today. [Operator Instructions] As a reminder, this conference call is being recorded for replay purposes. At this time, I would now like to turn the call over to Ms. Kelly Whitley, Director of Investor Relations. Please proceed.

Kelly Whitley

Thank you, operator. Good morning, ladies and gentlemen. Welcome to Ultra Petroleum's First Quarter Earnings Conference Call. Our call this morning will reaffirm Ultra's ongoing goal to deliver profitable growth for our shareholders. This theme will be reinforced by each of today's speakers.

On the call with me are Mike Watford, Chairman, President and Chief Executive Officer; Mark Smith, Senior Vice President, Chief Executive -- Chief Financial Officer; Bill Picquet, Senior Vice President, Operations; Doug Selvius, Director, Exploration; and Brad Johnson, Vice President, Reservoir, Engineering and Development.

Before turning the call over to Mike, I'd like to cover a few administrative items. First, this call will contain forward-looking statements that involve risk factors and uncertainties detailed in our SEC filings. All statements other than statements of historical facts included in this call are forward-looking statements. Also, this call may contain certain non-GAAP financial measures. Reconciliation and calculation schedules for the non-GAAP financial measures can be found in our 10-K and other filings with the SEC available on our website.

Second, we filed our 10-Q with the SEC this morning. This is now available on our home page, or you can access it using the SEC's EDGAR system. Third, we will be participating in some conferences over the next few weeks. Please check our website to view updated presentation and listen to webcast. Finally, our Annual Shareholders Meeting will be held on May 25. We hope that each shareholder has received their proxy materials, and we urge you to vote for the proposals being submitted in the proxy.

Now let me turn the call over to Mike.

Michael Watford

Thanks, Kelly. Good morning, and welcome. We're off to a good start at Ultra Petroleum in 2011 with production, cash flow and earnings up year-over-year. We're continuing our history of strong margins and returns with a first quarter cash flow margin of 72% and a net income margin of 29%.

In our tight-gas play in Southwestern Wyoming, we continue to improve operational efficiencies with faster drill times, innovative pad designs and 24/7 operations on drilling completion and now at workovers. 1,500 wells have been drilled over the past 12 years, with 5,000 to go, the world-class asset that positions us for low cost and strong margins. Bill has the update.

In our Marcellus shale play in North Central Pennsylvania, we see accelerating growth. 2011, we will double the number of net producing wells and increase production by 2.5x. Already, our first quarter 2011 Pennsylvania production equals half of last year's total annual Pennsylvania production, with most of 2011's program back-end loaded.

Our decline curves are getting flatter, and our EURs are increasing. It appears that Nelanseul's [ph] year end 2010 estimate of the amount of natural gas recoverable of 50% of our acreage of approximately 5 trillion cubic feet may be low. Doug has more details.

Now I'll ask Mark to share some financial commentary.

Marshal Smith

Thanks, Mike. Good morning. As Mike outlined and as you've seen from our press release, we had a very good quarter despite weak natural gas prices. We continue to see strong performance in the field with ongoing improvement and efficiencies, and we continue our strong organic growth, all while maintaining our industry-leading margins and returns while preserving our financial flexibility.

In terms of natural gas price for the quarter, our realized corporate natural gas price before the effective hedges decreased 20% year-over-year to $4.29 per Mcf. Yet I want to emphasize that this price registered 104% of Henry Hub for the quarter, well above our prior guidance range. Our natural gas hedge position has improved our average realized gas price by $0.84 per Mcf or 20% to $5.13 per Mcf. Condensate prices registered to $84.24 per barrel for the quarter.

Our production was up 15% on a comparable year-over-year basis to 55.8 Bcfe during the first quarter, well within our guidance range and in the face of inclement weather. This in turn was the primary factor driving our 11% increase in revenues, including the effects of our hedges of $302.3 million.

From a cost perspective, all of our costs were within our guidance ranges. As a result, our operating cash flow increased 15% over prior year levels to $216.3 million, providing an operating cash flow margin of 72%, up from 69% in the first quarter of 2010.

Cash flow per diluted share registered $1.40 during the quarter. Adjusted for our unrealized gains associated with the mark-to-market position on our hedges, our net income registered $87.6 million for the quarter for a 29% margin and $0.57 per diluted share.

With increased activity in Pennsylvania, our corporate tax rate increased from 35.5% to 35.9%. This resulted in a onetime noncash adjustment to our deferred tax provision that had the effect of increasing our effective tax rate for the quarter to 39%. Absent this adjustment, our earnings would have registered $0.59 per share.

In terms of breakeven levels, our net income breakeven is now $2.79 per Mcfe, with cash flow breakeven at $1.22 per Mcfe. Our adjusted return on average capital employed on an annualized basis for the first quarter was 13%, and our adjusted return on equity was 31%.

Cash provided by operating activities during the quarter amounted to $184.6 million with cash used in investing activities totaling $320.7 million. Of this, $305.7 million was directed to oil- and gas-related investments.

From a balance sheet perspective, we continue to be very well positioned. As of the end of the quarter, we had $22.9 million of cash and cash equivalents on hand and $88 million borrowed on our bank facility at an interest rate of roughly 1.5%. Overall, our debt capacity is in excess of $2.5 billion, providing us with just under $1 billion in unused senior debt capacity.

I want to point out that unlike some of our peers, we don't see ourselves with pipeline or processing restrictions in either of our primary operating areas.

In Wyoming, we continue to see the Ruby pipeline on track for completion in mid-summer, increasing Rockies' takeaway capacity by 1.5 Bcf per day followed by the Kern River apex expansion of 0.3 Bcf a day. After these additions, we see excess takeaway capacity from the region at roughly 4 Bcf a day. All of this is occurring in the face of declining production in the region, so we see this excess capacity situation extending for quite some time.

In Pennsylvania, at the end of the quarter and together with our partners, we had over 1.1 Bcf per day of interconnect capacity on 5 different pipelines. We see this going to over 1.3 Bcf a day of interconnect capacity during the second half. We believe that working with our partners, we have assembled what may be the most diversified set of pipeline interconnects in the Marcellus play. Again, we're in the Northern Pennsylvania area, in the dry gas window of the play that don't require any midstream processing infrastructure.

Moving to hedging. As detailed on Page 4 of our financial and operational press release, we have approximately 148 Bcf or roughly 76% of our remaining 2011 forecast natural gas production hedged, with fix priced swaps at a weighted average price of roughly $5.19 per MMbtu. For calendar 2012, we have about 110 Bcf hedged at a price of roughly $5.03 per MMbtu.

I'll wrap up my comments by observing that as we look towards the remainder of 2011, we believe we're well on our way to meeting our objective of better than 20% growth in adjusted earnings and cash flow, and we see double-digit growth continuing in 2012.

Now I'll pass it off to Bill for an update on our operations.

William Picquet

Thanks, Mark. Wyoming in the first quarter, Ultra brought on stream 57 gross, 35 net new producing wells. The average initial 24-hour sales rate for these new Pinedale producers, 6.8 million cubic feet per day. Ultra's operated Pinedale wells averaged 7 million cubic feet per day, while the non-operated wells averaged 6.1 million cubic feet per day. We drilled a total of 59 gross, 32 net new wells during the first quarter.

Our drilling performance continues to improve. Reduced drill times are allowing us to sustain excellent cost performance, upward pressure and cost of services.

We've averaged $4.8 million per well in our operated program in Pinedale during Q1 2011. First quarter, we averaged just under 13 days spud to TD for Ultra-operated wells, a 17% improvement over the average for Q1 2010. This is a new record for our first quarter drilling performance. We accomplished this in spite of the most challenging winter weather we've faced in quite some time in Pinedale.

During the first quarter, our average rig-release to rig-release was 16.5 days, down 16% from our Q1 2010 average. This improvement is even more impressive when considering our average time to drill this quarter, including several rig moves undertaken during winter conditions that slowed our moves from pad to pad.

For the quarter, over 90% of our wells were drilled in less than 15 days spud to TD, demonstrating consistency across -- performance across the entire rig fleet.

We continue to whittle away at our average drill time, pushing the average number of days down using a process focused on improving each segment of the drilling operation. Our record well currently stands at just under 9 days spud to TD. Our team is continuing their success by embracing changes in technology and the operating practices while closely monitoring results. This ensures that we continue to find the best in fit performance, directional control as well as other applications of drilling technology and operations.

We tailor our drilling programs specifically in each area of the field. We continuously evaluate the designs for new opportunities. For example, in Warbonnet this winter, we're using our slim-hole design in an area that previously required big-hole designs. We were able to drill these wells with a more under-balanced mud system, allowing use of lower mud weights than previously experienced in the area. The end result was much shorter drill times and substantial savings per well.

We've developed unique alliances with our service providers, and our cost performance has been sustained, essentially flat Q1 2011 compared to Q1 2010, in the face of continuing upward pressure on our overall cost of services. Personnel cost and service cost are moving upward, and so far, we've offset these increases with efficiency improvements.

Completion performance in our Pinedale operations has also been outstanding. During Q1, we continued our fast pace of activity in our operated frac program, completing a total of 46 new wells, averaging 23 stages per well. Our cost average is just under $76,000 per stage during Q1 compared to $73,500 in the first quarter of 2010 and $74,000 per stage in Q1 2009. Keeping our cost essentially flat in our winter completion activity is impressive considering continued upward cost pressures and particularly, considering the more difficult weather conditions we encountered this winter.

In summary, we continue to find ways to improve our operating efficiencies into all phases of our Pinedale operations. Our drilling completions and production operation teams are very focused on these efforts and continue to produce excellent results.

With that, I'll turn things over to Doug for our Pennsylvania update.

Douglas Selvius

Thank you, Bill. During the first quarter in Pennsylvania, Ultra participated in drilling 31 gross and 17 net horizontal wells on its position of 260,000 net acres. This activity brings our total horizontal well count to 185 gross and 111 net wells. The company also participated in 27 gross and 14 net vertical wells. While our vertical activity is now winding down, our horizontal drilling is starting to ramp up, and I'll talk more about that in a few minutes.

One well of note during the quarter was our first horizontal test of the Geneseo formation. We drilled a 4,300-foot lateral in Western Tioga County that should be completed next month.

For the quarter, Ultra and its partners initiated production from 13 gross and 8 net Marcellus wells. These wells had an average lateral length of 5,173 feet and were completed with an average of 14 frac stages per well. Initial rates for the individual wells averaged 6.5 million cubic feet per day, which is slightly above our historical average of 64 million.

Ultra's total producing well count in the Marcellus is now 105 gross and 67 net wells. Net production for the quarter averaged 92 million cubic feet per day, which represents a 23% increase over the fourth quarter and a better than 400% increase over the first quarter of 2010.

Production rose steadily during the quarter to a peak of 109 million cubic feet per day, and we are currently at 101 million cubic feet because a handful of key wells are shut in for simultaneously operations. As these shut-in wells and a number of startups come online, we could see net production rates approaching 140 to 150 million cubic feet per day this summer.

A number of good things happened from a production standpoint during the quarter, and I would like to mention just a couple of them. Western Tioga County also drilled 3 of its longest laterals to date on the Pierson 810 pad. A 3H well with an effective lateral of 6,700 feet was recently completed with 27 frac stages, turns of sales at a rate of 10 million cubic feet per day. We are now completing 2 adjacent long lateral wells and should have them online by the end of the month.

These 3 wells are direct offsets to the Pierson 801 5H (sic) [Pierson 810 5H], which has an EUR exceeding 8 Bcf. It's one of our best wells in the field. This area is shaping up as a very high-value area. Our mapping effort confirm it as one of the sweet spots in our overall acreage position. It appears EURs for these new long lateral wells could be nearly twice our 3.75 Bcf type curve.

Western Lycoming County down through the south, a pad of 6 wells came online during late March and early April and residual IPs averaging 7.7 million cubic feet per day. These are very strong wells demonstrating much better performance than our current 5 Bcf type curve, and they seem typical of our results in the area.

Net production for all of Ultra's wells along the Clinton, Lycoming County line reached 46 million cubic feet per day during the first week of April. This rate is 40% over expectation and actually approximates our projected year end exit rates.

As most of our completions and startups still lie ahead of us down there, we're quite excited about these early results. Both well productivity and operational execution are well ahead of expectation.

This observation is true in other areas as well, and our overall Marcellus program continues to exceed expectation. We're also beginning to understand it better. We've learned that initial rates are not necessarily indicative of Ultra's well performance. We're consistently seeing wells demonstrate flatter declines in our current type curves and seeing EURs for most of our wells increase through time with additional production history.

For example, in our year end 2010 reserve report, our Ken-Ton 902-1H well with 60 days of production had an EUR of 3.8 Bcf. After 150 days of production, we now expect that well to produce 4.8 Bcf or 26% better.

Taking a look at the rest of the year, we expect both drilling activity and production volumes to increase going forward. We presently have 8 rigs active and plan to drill nearly 50 net wells in the next 2 quarters.

We're projecting up to 76 net wells for the entire year, and all are located in quality areas with good rocks and quick hook. Results so far this year are attributable to [indiscernible] strategy.

On the production side, initial startups for the second quarter should be 2 or 3x what we accomplished in the fourth quarter -- first quarter, excuse me. Our third and fourth quarters will also be very active. Our budget included this increase, and we remain on track with capital expenditures and well counts projected last quarter that indicated 75 net additional wells during the course of the year.

From a drilling standpoint, we continued to gain efficiencies during the quarter. Our time to drill from kickoff point to total depth decreased from 9.5 days down to 8.8 days despite the fact that our laterals were nearly 1,300 feet longer on average.

Well costs in Tioga and Potter Counties are averaging $4.3 million, while the deeper wells in Clinton and Lycoming Counties cost between $6 million and $7 million dollars depending on location and lateral length. Like other operators in the trend, we're experiencing cost pressure on the completion side but are managing to offset those increases in the drilling and water handling.

From a resource evaluation standpoint, we have now gathered information from 185 horizontal and 108 vertical wells. Much of this data is now starting to bear fruit. We've done extensive logging in 19 of our company-operated laterals. We've participated in 4 microseismic surveys. We've acquired 315 square miles of 3D seismic data, drilled 16 pilot holes with extensive logging suites. We've taken core from 14 wells. All of this data has been incorporated into studies that are starting to give Ultra a unique insight into the Marcellus resource.

It's become clear that regional geology and petrophysical studies work well for delineating broad general trends in regionally desirable areas. This approach falls short, though, when it comes to identifying localized sweet spots in high-value area.

As Marcellus performance varies from one location to another, Ultra's technical team has been focused on sweet spot delineation and are making good progress. By integrating our petrophysical data with a number of seismic attributes in the pilot study area, we've been able to model historical results and predict the results of recent completions with surprising accuracy. We are quickly expanding this study now to include our entire 3D database, and we will continue to test our model against prior results and future completions. As we go forward in this play, we expect this effort to enable us to concentrate our drilling program and capital investment in the most profitable area.

In summary, we remain very pleased with the results we've seen to date in our Marcellus program. Our knowledge base and our understanding continue to grow, and we fully expect these learnings to yield better efficiencies and continued strong results in 2011 and beyond.

With that, I'll hand it back to Mike for some closing remarks.

Michael Watford

Thanks, Doug. Let me share a few more comments and then open it up for questions. At Ultra, we have 2 concentrated assets characterized by low cost and strong margins. Nelanseul [ph] estimates 15 trillion cubic feet of recoverable natural gas with $22 billion in future development cost just in these 2 assets. We see more.

Our economics indicate that our 2011 capital expenditures for drilling and completing wells will generate an average internal rate of return of 40% at $5 natural gas prices. We continue to see the opportunity over the next 3 years while spending within cash flow to increase our production by 50% and to double our cash flow per share. I think the opportunity to continue the double-digit growth in production cash flow and earnings achieved in 2010 extends through this 3-year period. And as always, we want to make money first and grow second. Now for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Subash Chandra with Jefferies & Company.

Subash Chandra - Jefferies & Company, Inc.

So staying on topic there, it seems like that in this summer, you're sort of suggesting you'll blow through the Marcellus guidance for the year. And I was curious if that's accurate, if there's any sort of limiting factors in the back half takeaway or whatever or if that's going to be offset somewhat in the Pinedale and what the dynamics of maybe revising your guidance later this year might be.

Michael Watford

Subash, I think it's a bit of the -- we're still stung with what happened last year with Shell buying East Resources and kind of shutting down operations for 3 to 4 months as to why how we didn't hit our Marcellus production goal. But what you see is Ultra conservatism on our production guidance from the Marcellus through Pennsylvania in 2011. And if you're going to continue to see us under-promise and over-deliver, I think that would be the outcome. We are seeing a better performance of wells than what we have modeled in our production models. That's good. That's wonderful. So I mean, you're probably right. We probably will blow through it, but we're not -- we're only [indiscernible]. So we're going to have 3 to 4 months before we deal with it.

Subash Chandra - Jefferies & Company, Inc.

Okay. So the -- on the Pinedale side of things, nothing really has changed from your initial thoughts?

Michael Watford

No, Pinedale is doing fine. [indiscernible] the weather, but other than that, we're okay.

Subash Chandra - Jefferies & Company, Inc.

Right, the weather. Is there an opportunity to operate more in the Marcellus? We've seen the Chevron package with Chief, et cetera. I don't know what they paid, but it seems like there might be more big packages left out there. How do you guys think about that?

Michael Watford

Well, there's periodic packages, and there's one large package out there now, probably large or larger than Chief and some smaller packages. We continue to evaluate all of these, one of the issues. So yes, there are larger packages. I'm not driven to operate. I mean, I want to remind folks that we preferentially bought some non-operated acreage this time last year, I think February of last year. And right now, we are delighted with the results we're seeing in that -- and in our non-operated area. They said they wouldn't have many -- much production until the fourth quarter of 2010 and going into '11, because it's building up the gathering systems and bringing in the frac crews after they drill a number of evaluation wells. We're seeing excellent well after excellent well being drilled out there just beginning to come on and have any kind of productive life. So we are -- we're not pleased with our decision to spend a fair amount of money for -- in Ultra's bracket for a non-operating position. But there are some other opportunities out there, and we'll evaluate them. Our challenge is just how much inventory do we want.

Subash Chandra - Jefferies & Company, Inc.

Do you have an office in Pennsylvania? I can't recall.

Michael Watford

A very small one in a small town by the name of Wellsboro.

Subash Chandra - Jefferies & Company, Inc.

Okay. I mean, is there sort of a tactical reason you don't want to have to bulk up there in order to operate that sort of keeps you to the sidelines on operated acreage?

Michael Watford

There's no tactical reason, no.

Subash Chandra - Jefferies & Company, Inc.

And one final one for me. So we've heard -- I mean, these well results and Marcellus' are dramatically better as these quarters go by, and we've heard reasons like lateral targeting or particular structures out there, tighter perf clusters and inflation. So could you give a -- maybe a bit of a technical overview of what does seem to work and what seems most promising? And then on the gas side, on the takeaway side, where does all the gas go? I mean, is there an opportunity for some of this to make it into Canada? Or is this just going to push the gas that's further down the chain, whether its Haynesville or Woodford or whatever, push it down into oblivion?

Michael Watford

Doug, do you want to take on this particular challenge? And Mark, do you want to deal with the gas?

Douglas Selvius

In terms of what works and what seems to be the most promising, it's all about the rocks, and we're doing quite a bit of work in that regard. Clearly, the resource is very good down in that Lycoming, Clinton County line area, and we're seeing so many sweet spots across the trend also. But it's where the resource is better quality, thicker, higher pressure, better porosity. It's all those typical things.

Marshal Smith

On the gas marketing front, Subash, we think our acreage position is -- we continue to be very pleased with the pipeline infrastructure that overlays it. We're fortunate in having a web of pipes as I described in my commentary. It gives us direct access into some of the higher value markets in the U.S. I think that does have the effect of backing out other gas coming up from the Gulf Coast as well as gas originally targeted for that area code across Canada and down into the States. So then you get backed up in both regions, and I think that -- I think we're seeing the results of that, and we'll continue to see the results in terms of a further narrowing of basis differential and flattening of basis differential across the country. We see first racks open up and then subsequently, Ruby as we go through the summer.

Subash Chandra - Jefferies & Company, Inc.

Okay. If I can sneak one final one, and I apologize. The $7 million a day operated IPs, what is the EUR in the Pinedale that is related to?

William Picquet

Subash, this is Bill. In the first quarter, the EURs were a little bit lower, because we were completing a high percentage of 5-acre wells. But year-over-year, we expect the EURs to be about the same 2010 to 2011 as far as the program goes.

Subash Chandra - Jefferies & Company, Inc.

And what number was that? Can you remind me?

William Picquet

About 4.5.

Subash Chandra - Jefferies & Company, Inc.

Okay, great.

Operator

Your next question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

Following up on Subash's question on the Marcellus, you highlighted the lower, shallower decline rates that you're seeing. Can you be a little more granular? Are you just seeing wells holding at their initial rates? And for how long are you seeing them just fall immediately but at a lower decline rate than you would have expected? And then what type of geographic difference are you seeing? And is this something that you're seeing throughout your Marcellus area in terms of lower decline rates? Or is it focused on only a couple of them?

Brad Johnson

Yes, this is Brad. Regarding the Marcellus type curves flattening, we are seeing the wells, over time, perform much flatter than our original type curves. Our current type curves are -- have been using a 1.7 B factor. We're seeing performance that would suggest it's 1.5 or less on that hyperbolic exponent. What that means is your annual declines are lower than projected and more EUR and better, profitable returns, because more gas is being sold sooner. Regarding the different type curves, we basically have 2 areas: up to the North in Tioga County and down to the south from the Lycoming, Clinton area -- I mean areas. And northern area is 3.75 Bcf currently. Southern area is 5 Bcf. And that's attributable to the depth and pressures, their differences.

Brian Singer - Goldman Sachs Group Inc.

And are you seeing the same lower B factor in both areas? Or is that specific?

Brad Johnson

We're using the same hyperbolic shape in both areas.

Brian Singer - Goldman Sachs Group Inc.

I'm sorry. Let me rephrase. Are you seeing the same well results come in at a lower B factor at the 1.5 versus the 1.7 across the board? Or is that specific to one versus another?

Brad Johnson

No. we're seeing that across the board in all areas, slighter declines.

Brian Singer - Goldman Sachs Group Inc.

Great. And in the Pinedale, as you non-consent some of the partner wells, should we expect that your IP rates should be rising here and that the production growth may decelerate? Or can you talk a little bit about kind of capital allocation in the Pinedale?

Michael Watford

Sure. Regarding Pinedale, as Bill mentioned, our IPs are around 7 so far this year. And what we're seeing is the mix of wells where we're located on the Anticline, first quarter was dominated by 5-acre wells and also some wells located on the flank of the field as we progress the rigs compliant with the BLM regulations for moving rigs in Pinedale field. Regarding the non-consents, we have -- we continue to non-consent cluster our wells. Those that are -- don't meet our thresholds. We do that through the course of the year.

Brian Singer - Goldman Sachs Group Inc.

So that should then lead to IPs going up over the next few quarters as there's a greater focus on your non-operated wells?

Michael Watford

Right. So far, Questar has not completed wells this year. But really, the bigger driver is location in the Pinedale field as opposed to the non-consent mix of a start well.

Brian Singer - Goldman Sachs Group Inc.

Great.

Operator

Your next question comes from the line of Noel Parks with Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Just a couple of things. There was a comment made earlier in the Marcellus that you thought you'd get to a rate of 140 to 150 million a day. I missed over what time frame you thought you were going to get there?

Douglas Selvius

We could get there this summer.

Noel Parks - Ladenburg Thalmann & Co. Inc.

This summer. Okay, great. And you also mentioned that because of some of the modeling you've been doing, you are better able to predict the completion results. And you said that -- in the Marcellus. And you said you've had some surprising accuracy. Can you just talk a little bit more about that and maybe what some of the implications for that would be if you keep really being able to pinpoint what sort of returns, what sort of results you get on the wells?

Douglas Selvius

Sure. At this time, we're not going to get in just a lot of details. We do think that Ultra's in a unique position with our data set, because it is unlike most others out there. But -- we're looking at petrophysical property, seismic properties that we're observing and looking for ways to predict performance, and we've had some success. So now the implications that you were alluding to, pretty impressive. I mean, if we can hydrate our drilling program and put our wells in higher value areas based on what we're seeing with the seismic data, that's pretty impressive.

Michael Watford

Doug, why don't you show him the -- way we have -- why we have such a unique data set.

Douglas Selvius

Well, as we got into the play, our focus was on acquiring technical data. So we ran Schlumberger's EcoScope Tool in our first 17 or 19 wells, which gives you petrophysical data across a 4,300-feet section as opposed to just a point in the entire -- one point in space with the vertical well. And we've got a lot of that data other operators don't have. That was very useful helping us calibrate our size.

Noel Parks - Ladenburg Thalmann & Co. Inc.

And just to get a sense of sort of the investment you made, how much more did that add to the early well cost that you think maybe competitors didn't bother to spend?

Douglas Selvius

In the range -- because we were using it to steer our wells also, in the range of $200,000 per well probably, plus or minus.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Okay, got it. And when you talk about high-grading the acreage just given the size of your position, is there -- is it even within sight that you could get to a point that if you didn't decide to necessarily let go of some acreage since you have so much to drill that you might be able to sort of see a fringe of the acreage? Or just the comparative results would be just much more lackluster, and you might think of, I don't know, divesting or farming out more of that or something?

Michael Watford

That's very conceivable. I mean, that's the end of game here. We're not there yet, but that's where we're going with this, yes. High grade our acreage and we don't want to drill low-value, uneconomic areas. And if we can get to that point, that's what [indiscernible].

Noel Parks - Ladenburg Thalmann & Co. Inc.

Right, that's it for me.

Operator

Your next question comes from the line of David Tameron with Wells Fargo.

David Tameron - Wells Fargo Securities, LLC

A couple of things. First, new ventures, can you give us an update there? Any more color you can shed?

Michael Watford

Yes. I mean, Dave, I hesitate to give much color, but we spent a year now with our little new ventures group looking at lots of opportunities. The vast majority either didn't have the returns that we want, the returns that are at least equal with our current 2 assets, or we didn't have scale. But I mean, we'll say we're getting closer on a couple of very interesting ones. And they may involve a commodity other than natural gas, but we're not there yet. We're getting very close with some stuff that looks attractive to us.

David Tameron - Wells Fargo Securities, LLC

Okay. So any time frame?

Michael Watford

Well there is one, but I'm not going to tell you.

David Tameron - Wells Fargo Securities, LLC

Okay. Fair enough. Let me come back to the sort of Pinedale. And everyone keeps dancing around this, but the Street's looking at IPs a year ago, it came in at close to 10. We're looking at first quarter this year that came at 6.8. Even with the 5-acre wells being weighted in there on an average basis -- and I don't know if you've given exactly how many 5-acre wells you're drilling. But I mean, obviously, that's a big drop on IPs. And can you give us -- I know you've answered it twice already, but is there anything more you can give us as far as why those IPs are so much lower than a year ago?

William Picquet

Yes, David, I can address that. It really is location of Anticline. A year ago, we had -- really, 18 months ago, we had moved a number of rigs north of the river, right in the middle, on the cliffs of the Anticline, and they were drilling some of the stronger wells we had in our inventory. And that's why you were seeing those higher IPs in Q1 2010. Q1 2011 ramping up our 5-acre pilot program from last year those wells were coming online as well as having a number of wells being drilled on the flank, both on the west and east edge.

Michael Watford

Yes. We had the 5 rig moves during the winter, which was -- which we don't want to do again. We know that. But that was in different areas in the field, and this is -- again, we don't get to build -- we don't get to drill the best of the rest. We have more opportunities to drill in better areas than we ever did prior to this executive decision, but we still, basically, are dictated by the BLM as to where we go and when. We've got to drill right now. We've got to drill in some areas that are kind of fringy areas for the next, I don't know, 6, 8 months. I don't know how long it is. Probably longer than that -- you can clarify it.

Douglas Selvius

Yes, that's correct.

William Picquet

In the interest of drilling the poor quality wells and lower gas price environment is probably not a bad thing in the long term.

Michael Watford

Yes, not a bad thing for us. And the other thing that's going to happen towards the end of the year, where we're sort of forced to drill because of the schedule and the guidelines, we're going to be drilling on some pads where we have a pretty small working interest. That actually helps bring our capital down in the fourth quarter of 2011. We're going down south. Or if we can pick up some more condensate down here, but we've got a smaller working interest. So on a run rate, our Wyoming CapEx goes down the fourth quarter.

Douglas Selvius

Just one of the keys is the wells are turning out like we predicted. There's no big surprises here. So I want to emphasize that predictability is there.

David Tameron - Wells Fargo Securities, LLC

Okay. And Mike, if I go back a couple of years. And as you've noted, my sideburns are getting gray, so I'm getting a little old, but -- so maybe my memory is fading, but weren't you guys saying that what you have the EIS, that some of those -- if I go back to '07, '08, that some of those wells being drilled were coming in lower, because you weren't able to drill on some of that EIS acreage?

Michael Watford

That's exactly true. We got the director decision late in 2008 and you saw an increase in 2009 and in the first half of 2010. And now we're rotating because, well -- and now we're also drilling 5-acre wells that are a bit smaller. And now we're rotating in 2011 to some areas with part of the rig fleet that are less attractive. And that's not -- we're still drilling on balance very economic wells. And again, everything is coming in per our plan and forecast. So we're not concerned at all. This is -- I mean, we've said all along and then we'll still say all along of the 5,000 remaining locations, the average is going to about 4.5 Bs per well. And if we can drill those for $5 million, that's great.

David Tameron - Wells Fargo Securities, LLC

All right.

Operator

Your next question comes from the line of Ron Mills with Johnson Rice.

Ronald Mills - Johnson Rice & Company, L.L.C.

A question. You just alluded to CapEx. I know the first quarter CapEx run rate is a little bit higher than your full year. As we -- and you said the fourth quarter in the Pinedale will come down. How does it also look just corporate -- from a corporate standpoint if you look at the Marcellus and your operated versus your non-operated capital?

Michael Watford

Well, in Marcellus we have the same phenomena occurring, where the wells coming on production are backloaded towards the second half of the year or more particularly, probably the second, third quarter. But capital was more front loaded. As we get towards the second half of the year in Pennsylvania and Marcellus, we also have the same thing going on, where our run rate's a little less.

Ronald Mills - Johnson Rice & Company, L.L.C.

Okay. And I'm assuming then that you're still for the full year standpoint even with getting more wells drilled with efficiencies that your total CapEx for the year still is fairly unchanged at this point.

Michael Watford

Yes, I mean we're -- it's -- we're still comfortable with the $1.1 billion capital number for the year. We'll see what happens as we go through the year. And right now, in Pennsylvania, for example, Anadarko's a little ahead. Shell's a little behind. We'll see how that plays out over the course of the year.

Ronald Mills - Johnson Rice & Company, L.L.C.

Great. Also, I know as you've discussed, you look to be self-funded over the next 3 years and actually generating excess cash. It looks like in the past, you've been one of the companies that has bought back stock. Any views on other stock buybacks over the next couple of years or dividends or some sort of restructuring especially as you start becoming -- as you become more and more developed in the Pinedale?

Marshal Smith

Ron, this is Mark. Yes, good question. What you see out in 2013 is free cash flow. And as a management team, we continue to look at that very, very carefully. As you cited, there are a number of alternatives that we have. Do we ramp up new ventures activity? Do we acquire another leg of the stool? Do we give back cash to the shareholders either in the form of share repurchases or dividends? As you know, given our corporate structure, one of things we've been looking at for some time is ways in which we can get cash back in the hands of our shareholders more efficiently. We continue to make good progress on that, and I'm quite pleased at what we're seeing. So that's continuing to open up -- it has potential to open up opportunities for either share backs -- or share buybacks or dividends to the shareholders in a more efficient way than what we've done in the past. But if we find another very good productive area that could be good for us, you could very well see us executing on that as well.

Michael Watford

Well, let me help. I think a nice dividend on my 3.5 million shares would be a lovely thing to have happen.

Ronald Mills - Johnson Rice & Company, L.L.C.

I bet you do. All of my operational questions have been asked.

Operator

Your next question comes from the line of Mike Scialla with Stifel, Nicolaus.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

The Tioga County well that you think is north of 8 Bcf, that's a Ultra-operated well, is that correct?

Michael Watford

Correct.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

And you've talked about, Doug, long laterals in that sweet spot that you found. I'm just wondering are long laterals do you think limited to those kind of sweet spot areas. Or is there an application for them across more of your acreage?

Douglas Selvius

We're actually drilling long laterals all across our acreage with Anadarko down in Lycoming and Clinton. We're consistently drilling 6,000-plus foot laterals. And also, we'll be doing that up in Tioga and in our other JV as well. So we're drilling longer laterals all across the acreage.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

So that $6 million cost you talked about in your southern area reflects the longer lateral. And does the $4.2 million in the northern area reflect the longer lateral?

Douglas Selvius

You can't drill 6,700-foot laterals for $4.2 million up in the north. The $6 million to $7 million does cover them in the south. And drilling laterals that long up in the north the cost will be higher.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

$5-plus million? Or is it closer to the $6 million?

Douglas Selvius

$5 million to $6 million.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Okay. And then you talked about that $140 million to $150 million a day you might get to this summer. Is that really -- what's the gating factor there? Is it getting completion crews? Or does a lot of pipeline need to be put in place still?

Douglas Selvius

A large number of wells scheduled to come online. Completions scheduled to come online later this month and into June, mainly June.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

How would you handicap? I mean, do you see risk to getting those done? Or is it pretty much a slam dunk at this point?

Michael Watford

Pretty good shape.

William Picquet

Yes. A numbers of those wells are being completed or tubed up. No infrastructure build out really required. It's just same ops and timing. More frac crews active across the acreage. So there are frac crews in hand, and they're pumping right now.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Good. Okay. And Doug, you talked about the microseismic survey you did. Anything you can share with us there in terms of what that suggests and in terms of spacing?

Douglas Selvius

We haven't seen anything really to refute our opinions on spacing right now. We've got a number of pilots going across -- going on across our acreage. We've drilled some 500-foot space wells. As you know, we're doing additional 500-foot spacing down in Lycoming. We're doing 750-foot spacing on our own operated acreage, and we're looking at 500 and 750. So across the board, we're looking at spacing studies. Right now, I'd say based on what we've learned from our [indiscernible], perhaps 500 might be a little too close. 750, we're bringing a bunch of wells on right now, so we'll see what we get.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Okay. And can you talk a little bit more about your Geneseo well? And again, I think that's Ultra operated. Any activity taking place around you that's got you encouraged to want to test that? And I just wonder, too, how much acreage you think is perspective for the Geneseo at this point?

Douglas Selvius

Just a rough number. I'd throw out a number of 60% to 70%. The well drilled nicely. We had great gas shows while drilling, but that's about all you can say at this point. We'll have test information for you, probably -- well, next quarter for sure. We'll be testing it in June. There are other operators making the play, kind of watching what they -- we're encouraged by what we see so far, but it's really early.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

How about the Utica? Any plans to test that this year?

William Picquet

No. I mentioned, I think on the last call, the Utica is active under our acreage. It's gas bearing, and it's got the look you kind of like to see, but it's deep. It's 11,000 feet to probably as deep as 14,500, 15,000 feet in the southern part. It's out there. You need better than $4 gas to make the Utica.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Right. Okay. And then just one last one on the Pinedale. Bill, you talked about the area, I guess, around Warbonnet where you did the slim holes. Is that limited to just that Warbonnet area? Or do you think you'll try slim holes on the other parts of the Anticline? And what kind of performance difference -- are you sacrificing some performance to save cost by using slim hole? Or are you seeing any performance difference between those wells?

William Picquet

Actually, typically, we drill slim holes. This is just one particular area of the field that's relatively small that required an additional casing string in the past. So it's a small subset of our wells, but it's just an indicator that as we continue to drill up there, we continue to find new things to do and new ways to improve our efficiencies. And in this particular area, it's significant.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Great.

Operator

Your next question comes from the line of Leo Mariani with RBC.

Leo Mariani - RBC Capital Markets, LLC

You folks talked about first quarter production downtime, a lot of bad weather up in the Pinedale area. Can you guys quantify that downtime for us?

Michael Watford

Not in a production volume, no.

Leo Mariani - RBC Capital Markets, LLC

Okay. I guess in terms of your gas pricing, it looked like it was a pretty nice premium this quarter versus NYMEX. Just any color you have around that and what you guys think that's attributable to.

Marshal Smith

Leo, this just goes back to what I've been guiding on for many quarters now with the addition of REX and it being up and operational. We saw narrowing of basis differentials across the country. And when you combine our firming capacity on REX, that narrowing of basis differentials and then how much we're beginning to produce over in the Northeast itself, it all works to combine to give us a corporate basis differential that's, as I've been saying, 94% to 96% of Henry Hub in guidance. And we actually raised it 104% for the quarter.

Leo Mariani - RBC Capital Markets, LLC

All right. Could you guys give us a sense of what type of pricing you're getting up in Northeast Pennsylvania relative to Henry Hub?

Marshal Smith

Yes. It's -- I'd say in the last few weeks, it's been around 103% -- 102%, 103% of Henry Hub, maybe more at times.

Michael Watford

We have gas in the Tennessee there. We have gas in Dominion South there. We have more and more gas in the Transco there as we have more of those pads that Anadarko's bringing on those big wells. So I think he's referencing the Dominion South number, which is 103%. I think if you look at the Transco number, it'd be greater than that. In Tennessee, probably be about the same range. So we're probably 103% or better overall.

Leo Mariani - RBC Capital Markets, LLC

Okay.

Operator

Your next question comes from the line of Andrew Coleman with Madison Williams.

Andrew Coleman - Madison Williams and Company LLC

Thinking about that B factor that I think Brad was talking about earlier -- the B factor going from 1.7 to 1.5 in the Marcellus. I guess what the -- over what time period was that seen?

Brad Johnson

Yes, Andrew. This is really in the 60- to 150-day timing. We see the wells flattening out. Of course, as you know, that equation -- initial decline, deep factor, term of decline -- all factors into the EUR. But right now, our wells are just flat out producing platter.

Andrew Coleman - Madison Williams and Company LLC

Okay, great. And there -- I assume are these choked back at some -- the same choke rate or...

Brad Johnson

That's another point to bring up. We have variable operating conditions across the operators and across locations, whether it's pressure or some constraints, sometimes localized with the DI [ph] package, sometimes through simultaneous operations. We will have these wells constrained if an operator [indiscernible] approaches as well, so...

William Picquet

So that's typically in the early life of the well though. What Brad is talking about is the flattening occurs in a point in time once all those other factors are no longer an issue.

Andrew Coleman - Madison Williams and Company LLC

Right. And so I guess getting to the later point in time then, when that be B factor would certainly be more impactful, I guess, can we see that in the 60- to 150-day range? Or are we still perhaps seeing some facility constraints kind of impacting the early life of the well?

Brad Johnson

I think, generally, you get out 60 to 90 days, those early constraints are behind you. And each and every time we look at a well, we look at the curve.

Andrew Coleman - Madison Williams and Company LLC

Okay, excellent. And do you guys -- will you have access to a Blacks Fork 2 plant that's coming on that QP's bringing on in the fall?

Michael Watford

Well, I mean, the gas that we've -- the working interest that we have with Questar in the northern part of the field that they operate, they have the processing of that gas. And I don't think it's tied to which plant it goes to. It just goes to their plants. They have the rights, so we just get back our methane. We're kept whole in BTUs.

Andrew Coleman - Madison Williams and Company LLC

Okay. And could that have any impact then as well on I guess improving the basis differentials or your NGLs, the ones that you process? Do they factor into your oil revenues?

Michael Watford

We don't participate in NGLs. We're just kept whole. We just get our 100% methane. We get 100% of our BTUs back in methane. So we don't participate in any of the processing uplift or downlift as it is from time to time.

Andrew Coleman - Madison Williams and Company LLC

Okay. And is that the case in the Marcellus too on the NGL side?

Michael Watford

We own -- I mean we have a contract out there in the Marcellus, but its dry gas. It doesn't require processing to be marginable.

Andrew Coleman - Madison Williams and Company LLC

Okay.

Operator

Your next question comes from the line of Ray Deacon with Pritchard Capital Partners.

Raymond Deacon - Pritchard Capital Partners, LLC

I had a question about the change in the B factor and what that could imply for EURs across kind of the various areas in the Marcellus. It sort of sounds like you're looking at kind of midyear to make that kind of announcement. Is that fair?

Marshal Smith

Yes, I think that's a fair statement.

Raymond Deacon - Pritchard Capital Partners, LLC

Okay.

Michael Watford

It comes from sandbag or bread.

Raymond Deacon - Pritchard Capital Partners, LLC

I guess just what's the latest on timing on Ruby? And do you see any impact, positive on your Rockies realized pricing?

Marshal Smith

Yes. We continue to see it midsummer. I think it's on track for summer. We're seeing some of the same things here that we saw in the opening of REX. We don't think the market's given credit for the -- full credit. And we're beginning to see some of it in the curves, but we don't think it's getting full credit for operational aspects of the pipeline until it's actually up and running. But we think you're seeing some bases tightening as you into the -- go through the summer, Ray, if you look at the curves. But our experience with REX was that once it gets up and running, it'll be even more than what we're seeing now.

Raymond Deacon - Pritchard Capital Partners, LLC

Okay, got it. And I guess just big-picture thoughts. You mentioned the dividend before, but if gas stays in this range of $4.50 to $5, when does the Marcellus become free cash flow positive? And what would be sort of the priorities for uses of that free cash flow?

Michael Watford

Well, I guess, I mean on free cash flow, we have to -- I mean, if we stay at a $1.1 billion a year capital and if we assume for some simple reasons that it's sort of $600 million, Wyoming and $400 million, Pennsylvania, if that were the going-forward assumption for a long period of time that I think we -- right now, we're creating free cash in Wyoming and in Marcellus, it's second cash, and I think that gets back to even. With Marcellus, we have in '13-ish or halfway 2012. And basically, it's a function of how much capital we spend and what gas prices are, but yes. And what we do with the free cash, that's why we have the new ventures group. That's why we keep looking to see if there's returns out there that are equal to or greater than what we have. We were amazingly frustrated at the 15% to 16% returns in much of the oil shales that we looked at and the opportunities we had at $80 oil. So this just doesn't make sense to us. So we're -- we'll see what we can do with the free cash. But I mean -- we still -- beyond free cash, we have additional debt capacity. If our sort of 3-year plan is anywhere near reality, when we get out there, we'll have $1.5 million of debt capacity that we could also use to accelerate our position. So we have a number of alternatives to work.

Raymond Deacon - Pritchard Capital Partners, LLC

Right. Got it.

Operator

The next question comes from the line of David Heikkinen with Tudor, Pickering, Holt.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Yes, just a quick question thinking about the sweet spot identification, make sure I heard you right. So basically, you have seismic and then you did 17 wells of analysis that makes you more in a unique position. And each of those wells cost about $200,000 of incremental cost.

Brad Johnson

Yes, that's sort of a simplification of the process. It's a lot more than just the 17 -- the data we've got from the 17 laterals. We've got a lot of vertical wells too. But I guess what I can say is that without the 3D seismic, we'd be dead in the water. Does that answer your question? So it's a 3D-based analysis.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Okay. So how much influence do you have over your non-operating partners in selecting sweet spots?

Brad Johnson

Right now, we're still developing this process. But if they looked at it, they saw it, then we'd have a lot of influence.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Okay. So when you think about the sweet spot identification and where the wells will be, they'll be on your operated acreage at this point?

Brad Johnson

Right. So we're -- that might last for another month. We're rapidly expanding this into the other areas.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Okay. And so you have seismic over the Shell and the Anadarko acreage as well?

Brad Johnson

We do not have it over the Anadarko acreage. It will be available over the Anadarko acreage. We haven't made a decision firmly, one way or another, whether to buy it. All of the Shell acreage, by the end of the year, will be covered.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Okay. So if you think about your operated acreage that you do have seismic on, what percentage has sweet spots?

Brad Johnson

It's too early to say that right now, but it's -- based on what we've looked at right now, it's around 60%.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Okay, that's helpful. That's it.

Operator

Your next question is a follow-up from the line of Subash Chandra with Jefferies & Company.

Subash Chandra - Jefferies & Company, Inc.

I just want to make sure I got my math right. So when I look at your PUDs -- and I think you guys put PUDs on a 3 year. And out of the PV-10 report, if that's $3 billion, is that sort of $1 billion a year, but obviously you're spending $600 million now, it'll be back-end loaded? Or is that really on a 5-year? And I'm really trying to get an idea of how much of 2011, 2012 CapEx will be for PUD conversion.

Michael Watford

Well, let's -- let me help with that. I mean the capital program and the reserve report is plus or minus $1.1 billion a year. It's actually less than that first year in the way it was put together, and it was all wells in Wyoming. We didn't book any PUDs in Pennsylvania, because we have a plethora of additional PUDs to book in Wyoming, and we don't even need to get the ones in Wyoming if we're limiting ourselves to 3 years at a $1.1 billion budget. So that's the way the reserve report is put together. I wouldn't suggest to you that our drilling plans are to spend $1.1 billion a year in Wyoming drilling PUDs. That's clearly not what we're doing. We're drilling $600 million in Wyoming and $400 million in Pennsylvania right now.

Subash Chandra - Jefferies & Company, Inc.

So how does that work when your '11 actual CapEx is different than what's in the PV-10 report?

Michael Watford

We're just being in many different places. I mean, there's no requirement to go drill exactly what's in the reserve report.

Subash Chandra - Jefferies & Company, Inc.

Okay, I'll follow up later.

Operator

Your next question comes from the line of Brian Velie with Capital One Southcoast.

Brian Velie - Capital One Southcoast, Inc.

I have a quick question on Pinedale, the efficiency improvements that you're seeing and the well cost. They seem to be leveling off at about 4.8 for the last few quarters. During the same time, we're hearing a lot about upward pressure on service cost in a lot of places. Is this a cost that you think you can continue to lower? Or are you kind of up against it now and seeing service cost counter it?

Marshal Smith

Well, I guess the statement for this quarter was it leveled off versus increased service cost. We're still seeing improved efficiencies, and I suspect that we're reaching a point where the increased service costs are going to level off as well. There's going to be more horsepower available as far as frac equipment is concerned and those types of things going forward. I've been asked several times, "When are we going to reach the end as far as efficiency?" And I can tell you that in Q2, we're drilling them faster.

Brian Velie - Capital One Southcoast, Inc.

Okay, great.

Operator

Your next question comes from the line of Michael Bodino with Global Hunter Securities.

Michael Bodino - Global Hunter Securities, LLC

I think I'm going to follow up on Subash's question a little bit more. I know at year end, you had about 146 Bcf of PDPs booked in the Marcellus, and you had another I think it was 437 Bcf that technically qualified for PUDs at year end. Have you run any numbers regarding those 2 numbers on the new B factors on how your reserves would have changed at year end? And then number 2 is how big of a variation of B factor do you have across all your acreage? Is it quite significant? Or are we starting to move into a very tight standard deviation around the mean B factor that you're seeing?

Brad Johnson

Sure. This is Brad. Just to address year-end reserves, those were all run at a factor of 1.7, more conservative than what we're seeing right now in well performance. Across the acreage, we're seeing this similar observation, and all the wells are producing flatter than a 1.7. We do not have a significantly different shape of the hyperbolic curve across the acreage, but we do expect more new wells down south, where it's thicker and deeper. So we make that adjustment appropriately.

Michael Bodino - Global Hunter Securities, LLC

Okay. That helps me out.

Operator

[Operator Instructions] Your next question is a follow-up from the line of Mike Scialla with Stifel, Nicolaus.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Yes, actually my follow-up was asked.

Operator

At this time, there are no further questions in queue. I would now like to turn the call back over to Mr. Mike Watford for closing remarks.

Michael Watford

Thank you. I'd like to thank everyone who participated on the call today, in particular the ones on the other end of the phones. I appreciate your time and interest. We look forward to updating you on our second quarter results this summer, where we can talk more about Marcellus and hopefully Geneseo. And we hope everyone has a great day. Certainly, if anyone has still have questions, please call the Investor Relations group. Thank you.

Operator

Ladies and gentlemen, this concludes the presentation, and you may now disconnect. Thank you, and have a great day.

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